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INDIAN OIL COPORATION LIMITED
Summer Training Report
Submitted By : NARENDRA SINGH CHOUDHARY
Birla Institute of Technology
Atmospheric & Vaccum distillation (AVU)
Fludized catalytic cracking unit (FCCU)
Continues catalytic Reforming unit (CCRU)
Propylene recovery unit (PRU)
Bitumen blowing Unit (BBU)
Diesel hydro desulphurization unit (DHDS)
Diesel hydro treatment unit (DHDT)
Once through hydro cracker unit (OHCU)
Hydrogen generation unit (HGU)
Amine recovery unit (ARU)
Sulfur recovery unit (SRU)
Motor spirit quality unit (MSQU)
Process Flow of Mathura Refinery
Mathura Refinery, the Sixth refinery of Indian Oil
Commissioned in 1982 with a capacity of 6.0 MMTPA to
meet the demand of petroleum products in north
western region of the country. Refinery is located 154KM
away from Delhi. The major secondary unit provided
were Fluidised catalytic cracking unit (FCCU), Vis-breaker
unit (VBU), and Bitumen Blowing unit (BBU). A Diesel
hydro desulphurization unit (DHDS) commissioned in
1999 for production of HSD with low sulfur content of
0.25% wt (max). with the commissioning of Once
Through Hydro Cracker unit (OHCU) in july 2000, capacity
of Mathura Refinery was increased to 8.0 MMTPA.
Diesel hydro-treating unit (DHDT) & MS quality
upgradation unit (MSQU) was installed with world class
technology from UOP in 2005 for production of Euro-III
grade HSD & MS w.e.f. For upgrading environment
standards, old Sulphur Recovery units (SRU) were
replaced with new sulphur Recovery units with 99.9%
recovery in the year 1999.
SERVO lubricants & greases
Marine Fuels & Lubricants
Indian OIL is not only the largest commercial enterprise in the
country it is the flagship corporate of the Indian Nation. Besides
having a dominant market share, Indian oil is widely recognized
as India’s dominant energy Brand and customers perceive
Indian oil as a reliable symbol for high quality products and
Benchmarking quality, quantity and service to world class
standards is a philosophy that Indian Oil adheres to ensure that
customers get truly global experience in India. Our continued
emphasis is on providing fuel management solutions to
customers who can then benefit from our expertise in efficient
sourcing and least cost supplies keeping in mind their usage
patterns and inventory management.
Retail Brand template of Mathura refinery are XtraCare(urban),
Swagat(highway) and Kissan Seva Kendras(rural) are widely
recognized as pioneering brands in the Petroleum retail
segment. Indian Oil;s leadership extends to its energy brands
Indane LPG, Servo Lubricants, Autogas LPG, XtraPremium
Banded Petrol, Xtramile Branded Diesel, XtraPower Fleet card,
Indian Oil Aviation and XtraRewards cash customer loyalty
OIL Movement And Storage (OM&S)
Oil movement and storage (OM&S) having two sub division OM&S1 and
OM & S 1
Functions of OM&S 1
Receipt storage, accounting preparation and supply of crude oil to
Supply of feeds to secondary processing units.
Blending of intermediate products.
Supply of intermediate fuel oil to units.
Measurement of petroleum products gauging sampling etc.
Dispatch of finished products.
LPG+ Propylene - 3.15%
Light Aromatic Naphtha- 4.77%
Motor Spirit (1%) -8.33%
Motor Spirit (3%) -3.97%
Aviation Turbine Fuel -6.35%
Superior Kerosene Oil -6.80%
High Speed Diesel (.05% S)-13.61%
High Speed Diesel (.25% S)-27.60%
Middle Distillates -(54.54%)
Furnace Oil -7.59%
Gross Fuel Loss-6.64%
Net Fuel & Loss -3.74%
The products produced by blending are motor spirit (88octane and 93
octane) high speed diesel (low sulphur and high sulphur),light diesel
Waste water,oily water &oil spillages from pump.slabs & tank farmsis
brought to the effluent treatment plant where oils is separated and is
pumped to slop tanks.
Storage Tanks For Different Products
Aviation Turbine Fuel (301-305)
Superior Kerosene Oil (401-405)
Heavy Vaccum Gas Oil (851-853&503)
Vaccum Slop (707&708)
Furnace Oil (703-712)
Crude Tank (001-006)&(007-008)
Different pipelines to dispatch the products
MJPL (Mathura Jalandhar Pipe lines)
MBPL (Mathura Bharatpur Pipe lines)
MTPL (Mathura Tundla Pipe lines)
MMT (Mathura Marketing Terminal)
GANTRY (Tank Wagon Loading)
Different types of tanks used to store products
Fixed Roof Tank -used for storage of black oil, diesel, FO
Floating Roof tank – used for storage of light products like, MS
Floating cum fixed roof tank - used for storage of ATF
Atmospheric and Vaccum Distillation Unit (AVU)
The crude distillation unit was designed for desalting and
primary distillation of light Arabian crude and North Rumalia
mixture in the proportion of 1:1. The nominal designed capacity
of the unit was 6MMTPA of the above crude on mixture.
However the designed provided a possibility of processing
7MMTPA of crude of containing 2% weight of gas. Process
calculation, sizing of vessels and equipment was made for the
same. The unit has been revamped in different stages to raise
its capacity and to process different types of crude including
indigenous crude from Bombay High. Subsequent to these
revamps, the nominal capacity of the unit stands at 8 MMTPA
for processing imported Middle East crude and 7MMTPA for
processing Bombay High. Based on 50:50 processing of
imported and BH crudes in blocked out operation, the nominal
capacity of the unit stands at 7.5 MMTPA. The unit has been
designed to produce the following cuts: LPG To be sent to
Merox treating unit
DESCRIPTION OF PROCESS FLOW SCHEME:
FEED SUPPLY: crude is stored in eight storage tanks (six having a
nominal capacity of 50,000 m3 each and remaining two are of
65,000m3 each). Booster pumps located in the off-sites are used to
deliver crude to the unit feed pumps. Filters are installed on the suction
manifold of crude pumps to trap foreign matter. For processing slop,
pumps are located in the off site area which regulate the quantity of
slop into the crude header after filters. Provision to inject proportioned
quantity of demulsifier into the unit crude pumps suction header with
the help of dosing pump is available.
FEED PREHEAT (PRE-DESALTER) CIRCUIT: Crude oil from feed pumps is
charged to heat exchangers in two parallel streams.
DESALTING: Desalting is a purification process used for the removal of
salts, inorganic particles and residual water from crude oil and thereby
reducing corrosion and fouling of equipments. These impurities are
brought along with the residual water content of the crude oil. Water
drops ordinarily are so small that simple gravity settling is very poor .in
an oil pool, the molecules that are least similar to the bulk of oil are
subjected to less intermolecular forces. Being less attracted to the inner
body of the oil, the exceptional material will be rejected to an inter-face
of the oil/water drops. Such rejected surface active materials comprise
a physical barrier that prevents water drops from getting close enough
to bring about coalesce. Before the drops can coalesce the stabilizer
film must be reduced in thickness, tenacity and therefore ruptured. The
electric field is a powerful tool for overcoming the resistance of
stabilizing films. The collision and coalescence of drops is accomplished
by an induced dipole attraction between them. As the droplets then
approach each other, the force between them becomes very great. The
stabilizing films are squeezed between the drops and coalescence is
rapid. The large water droplets produced fall through the oil phase at a
faster rate. This desalting process consists of three main stages, viz.
heating, mixing and settling.Crude oil is heated to 125-135 °C in the
pre-desalter heat exchanger train. Water is injected under flow control
upstream of mixing valves. Provision is given at crude pumps suction
also to facilitate break-up of tightly bound oilwater emulsion. Brine
outlet from the desalters is cooled in air cooler and water cooler before
final disposal. Desalter pressure is controlled between
11-12 kg-12 kg/cm2 by a conyrol valve located at the discharge end of
the crude feed pumps.
POST DESALTER CRUDE PREHEATING: Desalted crude from desalter is
pumped by post desalter pumps into streams going through a second
train (two in parallel) of heat exchangers. Downstream of the
exchangers trains, crude oil streams combine to average out the
temperature. Normal preheat temperature is in the range of 230-250
FIRED HEATERS: the preheated crude is further heated and partially
vaporized in three parallel tubular heaters. Each furnace is four pass
heater with air preheater. Each furnace is provided with 14 burners
capable of firing FO and FG, either fully or partially. Convection section
has 8 rows of tubes with 8 tubes in each row. Two rows of shock tubes
just above the radiant section are plain tubes with out studs. In the
convection section 4 studded tubes are for the service of superheating
MP stream for strippers. The radiant box has 21 tubes in each pass.
Convection zone had 12 rotary and 12 retractable soot blowers in two
AIR PREHEATER SECTION: To recover waste heat from flue gases of
CDU and VDU furnaces four identical parallel stationary air preheater
units are provided and installed in parallel. At APH cold combustion air
will pick up heat flue gas poat tobeme routed to the burner could to the
burners for efficient combustion. Three FD fans each capable of 55% of
full load are provided with SCAPH in there discharge to heat the air
unto 45 °C. the combustion air requirement of each heater is controlled
by individual FICS damper located in the air duct to the respective
furnace. Load on the fans is varied by regulating the inlet guide vances.
Heaters are provided with slain temp O2 analyzer and draft gauges.
Furnaces are provided with different trip logic to save the equipments
under different abnormalities.
CORROSION INHIBITOR: A solution of corrosion inhibitor in light
hydrocarbon is required to be properly dispersed in vapor stream to
combat corrosion of the overhead system. Most of the inhibitor is
active in specific ranges closes to neutral.
DEMULSIFIER: the injection rate should be around 6-8 ppm on crude.
Fluidized Catalytic Cracking Unit (FCCU)
Objective: To convert Heavy Vacuum Gas Oil to valuable distillates like
LPG, Gasoline, Diesel by catalytic cracking in fluidized bed.
Feed: VGO/RCO/VR/Hydrocracker Bottom.
Catalyst: Silica & Alumina Zeolite Structure.
FCCU Product Yields:
Sl. No. Products wt%
1 Gas 2.3
2 LPG 14.7
3 Gasoline 41.3
4 HN 21.3
5 LCO 11
6 HCO 0
7 CLO 10.9
8 Coke 4
Temperature range : 490-550 deg
Pressure : 2-3 kg/cm2
In the newer designs for Fluid Catalytic Cracking Unit, cracking takes
place using a very active zeolite-based catalyst in a short-contact time
vertical or upward sloped pipe called the "riser". Pre-heated feed is
sprayed into the base of the riser via feed nozzles where it contacts
extremely hot fluidized catalyst at 1230 to 1400 °F (665 to 760 °C). The
hot catalyst vapourizes the feed and catalyzes the cracking reactions
that break down the high molecular weight oil into lighter components
including LPG, gasoline, and diesel. The catalyst-hydrocarbon mixture
flows upward through the riser for just a few seconds and then the
mixture is separated via cyclones. The catalyst-free hydrocarbons are
routed to a main fractionator for separation into fuel gas, LPG, gasoline,
light cycle oils used in diesel and jet fuel, and heavy fuel oil.
During the trip up the riser, the cracking catalyst is "spent" by reactions
which deposit coke on the catalyst and greatly reduce activity and
selectivity. The "spent" catalyst is disengaged from the cracked
hydrocarbon vapours and sent to a stripper where it is contacted with
steam to remove hydrocarbons remaining in the catalyst pores. The
"spent" catalyst then flows into a fluidized-bed regenerator where air
(or in some cases air plus oxygen) is used to burn off the coke to restore
catalyst activity and also provide the necessary heat for the next
reaction cycle, cracking being an endothermic reaction. The
"regenerated" catalyst then flows to the base of the riser, repeating the
The gasoline produced in the FCC unit has an elevated octane rating but
is less chemically stable compared to other gasoline components due to
its olefin profile. Olefins in gasoline are responsible for the formation of
polymeric deposits in storage tanks, fuel ducts and injectors. The FCC
LPG is an important source of C3-C4 olefins and isobutane that are
essential feeds for the alkylation process and the production of
polymers such as polypropylene.
In this process Heavy Gas Oil cut (Raw Oil) from Vacuum Distillation
Section of AVU is catalytically cracked to obtain more valuable light and
middle distillates. The present processing capacity of the unit is about
1.48 MMT/Yr. It consists of the following sections:
Gas concentration section.
The unit is designed to process two different types of feed i.e. Arab Mix
HVGO and Bombay High HVGO.
Significance of Gas concentration section:
In Gas con section the separation of LPG and stabilization of naphtha is
achieved in steps as follows:
The overhead gas is compressed by WGC to about 13 kg/cm2
The LPG component in the compressed gas is absorbed by overhead
naphtha in the absorber and send to stripper.
The lighter ends C1 and C2 are stripped off and the stripper bottom is
send to debutanizer.
The debutanizer separates the LPG and stabilize the naphtha.
Key aspects of Operation and Maintenance:
Catalyst circulation is established by fluidization. Handling of
hydrocarbon and air side by side at very high temperature (500-700o
Reactor and regeneration section is separated by delicate pressure
balance. Coke deposited on the catalyst is burned off in regenerator at
650 deg c.
Separation of fine catalyst in hydrocarbon vapoursand in flue gas by
cyclones. Erosion is a common phenomena in Cyclone and slide Valves.
Continues Catalytic Reforming Unit (CRU)
Objective: To Upgrade the Naphtha to High Octane MS Component
Feed: 85-160 Deg C cut Naphtha / Visbreaker Naphtha
Catalyst: Ni-Mo Oxides for NHTU Reactor
Pt-Sn or Re for Reforming
Sl. No. Products wt%
1 Motor Spirit 92.6
2 Hydrogen rich gas 6.8
3 LPG 0.55
Temperature range: 490-540 C
System Pressure: 2.0 -30 kg/cm2
A catalytic reforming process converts a feed stream containing
paraffins, Olefins and naphthene to aromatics. The product stream of
the reformer is generally referred to as reformate. Reformate produced
by this process has a very high octane rating. Significant quantities of
hydrogen are also produced as a by-product.
The whole CRU can be divided into three subunits as:
Naphtha Splitting Unit (NSU)
Naphtha Hydro-treater Unit (NHU)
Catalytic Reforming Unit
NAPHTHA SPLITTING UNIT
This unit has been designed to split SR naphtha (144 MT/hr for BH and
95 MT/hr for AM) to C5-80 o
C and 80-115 o
C cut. Due to the restriction
on Benzene content in the final product (motor spirit), the IBP of the
heavier cut is raised to approximately 105 o
C. NSU can be operated with
naphtha directly from AVU (hot feed) and from OM&S (Cold feed), it
can also be operated using both the feed simultaneously. For removal
of benzene, the gasoline from storage tanks and CDU is sent to a
column, containing 40 valve trays, which is called naphtha splitter. The
bottom product of naphtha splitter is sent to the NHU.
NAPHTHA HYDROTREATER UNIT
The purpose of Naphtha hydrotreater is to eliminate the impurities
(such as sulphur, nitrogen, halogens, oxygen, water, olefins, di-olefins,
arsenic and metals) from the feed that would otherwise affect the
performance and lifetime of reformer catalyst. This is achieved by the
use of selected catalyst (nickel, molybdenum) and optimum operating
conditions except for water, which is eliminated in stripper.
In this unit, the naphtha coming from the NSU is mixed with H2 which
comes from the reforming unit. This mixture is heated to 340 O
C in the
furnace and then passed to the hydrotreater reactor at a pressure of 22
. In the reactor, there are two beds of catalyst. In one bed, the
unsaturated hydrocarbons are converted to saturated hydrocarbons
and in the second bed impurities like N, S, and O are converted to NH3,
H2S and H2O respectively. The effluent of the reactor is sent to stripper
section to eliminate the light end, mainly the H2S and moisture from
the reformate feed. The light gases from the top of stripper are sent to
amine wash unit. There is a reboiler attached to the bottom of the
stripper, which maintains the heat requirement. The bottom product of
the stripper is either sent to storage or the reforming unit.
Feed for the Reforming unit (94 m3
/hr at 14 kg/cm2
and 110 o
received directly from hydrotreater stripper after heat exchanger. The
filters must be provided for the protection of the welded plate
exchanger. Feed is filtered to remove any foreign particles. At the D/S
of the feed filter, chloriding agent and water injection are done. CCl4
solution of 1% in reformate is dosed by pump. Dosing @ 1 ppm wt CCl4
in feed is done when continuous regeneration unit is down. Water
injection (not on regular basis) is done to maintain Cl-OH equilibrium on
the catalyst when regenerator is out of service.
Feed mixed with recycle H2 stream gets preheated in PACKINOX
exchanger from 91o
C to 451o
C by the effluent from 3rd Reactor which
gets cooled down from 497o
C to 98o
Due to the endothermic nature of the reforming reactions, the overall
reforming is achieved in stages with inter stage heater provided to raise
the temperature. There are three Reactors (15R-1, R-2 & R-3) each
provided with reaction heater.
Merox Unit (Mercaptan Oxidation)
Mercaptans are undesirable in the final products because it effects
their stability, sulfur content, odour etc.
Objective: Chemical treatment for conversion of Mercaptans to di-
Feed: ATF, Gasoline, VB Naphtha and LPG.
RSH + 1/4 O2 = ½RSSR + ½H2O
The MEROX process efficiently and economically treats petroleum
fractions to remove mercaptan sulfur (MEROX extraction) or to
convert mercaptan sulfur to less-objectionable disulfides (MEROX
sweetening). This process can be used to treat liquids such as liquefied
petroleum gases (LPG), natural-gas liquids (NGL), naphtha, gasoline,
kerosene, jet fuels, and heating oil. It can also be used to treat gases
such as natural gas, refinery gas, and synthetic gas in conjunction with
conventional pre-treatment and post-treatment processes.
Straight-run LPG, gasoline and kerosene fractions obtained from
atmospheric distillation may contain hydrogen sulfide and mercaptans,
the extent of which mainly depends upon the type of crude processed.
Similar products from secondary processes such as FCC also contain
hydrogen sulfide and mercaptans to a greater degree compared to
straight-run products. Hydrogen sulfide is corrosive and should be
removed in order to meet specifications on corrosion rate. The
specification for LPG, gasoline, Kerosene and ATF include copper strip
corrosion test which is a measure of rate of corrosion on copper
containing materials. Mercaptans are substances with obnoxious odor
and, therefore, in order to handle and store them, mercaptan level will
have to be brought down to an acceptable odor level. The
specifications of above products include 'Doctor Test' which must be
negative and is generally related to the extent of mercaptan present.
Hydrogen-sulfide can be easily removed by washing with dilute caustic
solution. However, for reducing the mercaptan level many processes
are available like:
Alkali-wash is effective only if low molecular weight mercaptans are
involved. Hydro desulphurization is normally employed only if
reduction of total sulphur level is also required. Both investment and
operating costs are higher in case of hydro desulphurization.
a) MEROX PROCESS DESCRIPTION
The Merox process licensed by M/S Universal Oil Products Co., (UOP),
USA, is for the chemical treatment of LPG, gasolene and distillates to
remove mercaptans into disulphides. The removal of mercaptans may
be either partial or full. The chemical treatment is based on the ability
of Merox catalysts to promote the oxidation of mercaptan to disulphide
using air as the source of oxygen. The overall reaction is as follows:
2RSH + 1
/2O2 -> RSSR + H2O
The oxidation is carried out in the presence of an aqueous alkaline
solution such as either sodium hydroxide or potassium hydroxide. The
reaction proceeds at an economical rate at normal rundown
temperature of refinery streams.
Low molecular weight mercaptans are soluble in caustic solution and
therefore when treating LPG and light gasoline fractions, the process
can be used to extract mercaptan to the extent, they are soluble in
caustic. Extraction of mercaptan reduces the sulphur content of the
treated product. Alternatively mercaptans can be converted to
disulphides without removing any sulphur from the treated stock in
which case the operation is referred to as sweetening. In the treatment
of heavier boiling fractions such as heavy naphtha and kerosene only
sweetening is possible.
MEROX PROCESS EQUIPMENT:
In order to understand the function of various Merox process
equipment. the equipment can be broadly divided into following
1. Pretreatment for removal of hydrogen sulphide and naphthenic
acids, if present. The method varies with properties and
conditions of feedstock and in some cases may not be required.
2. Extraction section where required, for removal of caustic soluble
mercaptans and thus reduce sulphur in the treated product.
3. Sweetening for conversion of mercaptans to disulphides. For a
given capacity plant, the Merox reactor size can vary depending
on the case of sweetening due to the type of mercaptans present
and also on product requirement.
4. Post-treatment to remove caustic haze and to control properties
not affected by Merox process. Hence post-treatment needed
depends on products, utilisation and type of contaminants
present in the feedstock.
5. Taking each section in turn, function of each equipment can be
Petroleum fractions may contain hydrogen sulphide and stocks boiling
higher than 180°C may also contain naphthenic acids. Hydrogen
sulphide is not a catalyst poison as such, but will dilute the caustic
containing Merox catalyst by reacting with caustic. Further it blocks
some of the catalyst activity sites slowing down the normal reaction
and also consumes part of the oxygen available. Hence, it is
recommended that hydrogen sulphide is removed by washing with
dilute alkali solution before the distillate is sent to reactor for
Naphthenic acids also interfere with treating operations and must be
removed prior to treatment. The reactor contains caustic and if
naphthenic acids are not remove they form sodium naphthenates
which coat the catalyst and block the pores. For removal of napthenic
acids, the procedure used is to wash with dilute caustic. Dilute caustic is
used so as to avoid formation of emulsions. There could, however, be
some carry-over of haze depending on the acidity of stock treated. The
haze can easily be removed by coalescing through a sand filter.
Feedstocks, where carry-over of water from distillation units can be
expected must be passed through a coalescer for removal of suspended
water prior to caustic wash, which would otherwise dilute the caustic
used for pretreatment.
As previously stated, low molecular weight marcaptans are caustic
soluble and can easily be removed by washing with caustic in a counter
current tower. Improved extraction is favored by:
High concentration of caustic.
Lower molecular wt. of mercaptans
Type of mercaptans, viz. normal mercaptans are easily extractable,
tertiary mercaptans least extractable and secondary being in between.
The mercaptan enters the caustic solution and reacts as follows:
RSH + NaOH <-> NaSR + H2O
This is being a reversible reaction the degree of completion of reaction
is governed by normal equilibrium laws.
The sodium mercaptide is readily oxidised to disulphide in the presence
of Merox catalyst as shown :
2NaSR + l
/2O2 + H2O -> 2NaOH + RSSR
This is not a reversible reaction and the reaction rate is speeded up by:
Raising the temperature.
Use of excess air.
Increasing the intimacy of contact.
Increasing the catalyst concentration.
The oxidation of mercaptides is carried out in oxidiser in the presence
of merox catalyst. The disulfides oil, which is formed, separates out
from caustic as it is insoluble in caustic. Caustic can be reused for
extraction. The presence of Merox catalyst in extraction caustic does
not however, affect the amount of mercaptans extracted. and
extraction is dependent only on parameters explained earlier .
Sweetening can be defined as conversion of mercaptan sulphur present
in a hydrocarbon stream to disulphide sulphur without actually
reducing sulphur content of treated stock. The sweetening process is
based on the ability of Merox catalyst to promote the oxidation of
mercaptans to disulphides using air as the source of oxygen. The
reaction is as follows:
RSH + NaOH <-> NaSR + H2O
2NaSR + l
/2O2 + H2O -> 2NaOH + RSSR
As can be seen from reactions, the oxidation is carried out only in the
presence of alkali solution.
The Sweetening can be accomplished either in solid bed sweetening,
where the hydrocarbons and caustic are simultaneously controlled over
a solid support impregnated with Merox catalyst.
Liquid-liquid sweetening where hydrocarbon, air and caustic containing
Merox catalyst, air simultaneously controlled in a mixer.
Solid bed sweetening consists of a reactor, which contains a bed of
activated charcoal impregnated with Merox catalyst and kept wet with
caustic solution. Impregnation of catalyst on bed is achieved by
dissolving the catalyst with ammonia solution and pumping ammonia
solution over charcoal. Air is injected ahead of reactor and in the
presence of merox catalyst the mercaptans are oxidised to disulphides.
The reactor is followed by a settler which serves as reservoir of caustic.
Caustic is intermittently circulated from the settler over the catalyst
bed to wet the charcoal.
For liquid-liquid sweetening, the most common type of mixer used is
the orifice plate mixer, which is a vessel, fitted with a series of plates
with orifices. The vessel provides adequate residence time and the
orifice plates create enough turbulence to bring about the intimate
contact between hydrocarbon, caustic, catalyst and air. The problem of
accomplishing liquid-liquid sweetening is one of getting the difficulty
soluble mercaptans into the caustic phase for sufficient time to permit
their oxidation. The higher the molecular weight or the more highly
branched the mercaptan is, the more difficult it is to accomplish
necessary mixing. Hence heavy gasoline and Kerosene may have to be
treated using fixed bed reactor.
The product from the merox reactor will at times contain caustic haze.
Post treatment is required if the product is to go to storage, clear and
bright. In most cases provision of caustic settler and sand filter is
adequate to remove caustic haze. However, for treatment of ATF,
which has to meet stringent specification caustic must be removed by
water wash after caustic settling. Water wash removes entrained
caustic as well as water soluble surfactants, Water wash is followed by
a salt filter to remove entrained water and part of the dissolved water.
This may be followed by clay filter to remove copper and water
insoluble surfactants, if present in feed.
There are two types of Merox catalyst, each one being used for specific
service. Catalyst FB is to be used on units equipped with solid bed
sweetening reactors. Catalyst WS is used for liquid-liquid sweetening in
mixers. This is a caustic dispersible catalyst. This is also used for
oxidation of extraction caustic in oxidisers.
Propylene Recovery Unit (PRU)
Objective: To produce propylene from cracked LPG.
Feed: Cracked LPG from FCCU.
Brief Description of Process:
Propylene Recovery Unit at Indian Oil Corporation Limited, Mathura is
designed to produce Polymer grade propylene from cracked LPG, which
will be supplied from FCCU. It is a mixture of Propane, Propylene,
Butane, Butylene with some amounts of C2 & C5 hydrocarbons.
The process package is supplied by EIL. Production capacity of
Propylene is 34,460 MTA from 1,44,000 MTA of cracked LPG available
from FCCU (based on FCCU capacity of1.3 MMTPA considering 345
days/year operation). Purity of Propylene produce will be 99.7% vol.
Turn down ratio of the unit is 40%. The unit is designed to recover
97.5% of propylene in LPG feed for typical case.
Process Flow Sections:
For the purpose of description unit has been divided into following
1) Feed surge drum and depropanizer section i.e.separation of C4’S from
2) COS Hydrolyser
3) De-ethanizer section i.e. separation of low boiling hydrocarbons from
4) Propane-Propylene splitter section.
5) H2S removal from propylene.
6) Water adsorption section for propylene drying.
Sl. No. Products wt%
1 Propylene 14.6
2 LPG 85.4
Bitumen Blowing Unit (BBU)
Objective: To Produce different grades of Bitumen by air blowing of
vacuum residue at high temperature.
Bitumen is colloidal solution of asphaltenes and high molecular
gums in the medium formed by oils and low molecular gums.
Feed : Vacuum Residue
Typical Operating Conditions of Bitumen Blowing Unit:
Temperature Range : 230-260 Deg C
Pressure: 0.5 kg/cm2
Sl. No. Products wt%
1 Off-Gas 0.86
2 Recovered Liquid Cut 0.26
3 Finished Bitumen 98.99
Diesel Hydro Desulfurization Unit (DHDS)
DHDS (Diesel hydro desulphurization unit) is set up for the following
A step towards pollution control
To produce low sulphur diesel (0.25 w/w %) as per govt. directive
w.e.f. Oct. 1999.
Feed consists of different proportion of straight run LGO, HGO, LVGO
and TCO. Mainly two proportions are used:
74% SR LGO, 21% SR HGO, 5% SR LVGO
48% SR LGO, 24% SR HGO, 8% SR LVGO, 20% TCO
The DHDS unit treats different gas oils from various origins, straight run
or cracked products. The feed is a mixture of products containing
unsaturated components (diolefins, olefins), Aromatics, Sulfur
compounds and Nitrogen compounds. Sulfur and nitrogen contents are
dependent upon the crude.
The purpose of DHDS Unit is to hydro-treat a blend of straight run gas
oil and cracked gas oil (TCO) for production of HSD of sulfur content
less than 500 ppm wt.
The Hydrodesulphurization reaction releases H2S in gaseous
hydrocarbon effluents. This H2S removal is achieved by means of a
continuous absorption process using a 25% wt. DEA solution.
In addition to the desulphurization, the diolefins and olefins will be
saturated and a denitrification will occur. Denitrification improves the
product stability. The hydrogen is supplied from the hydrogen unit.
Lean amine for absorption operation is available from Amine
Regeneration Unit (ARU). Rich Amine containing absorbed H2S is sent
to ARU for amine regeneration.
Catalysts used for this process are HR-945 and HR-348/448.The HR-945
is a mixture of nickel and molybdenum oxides on a special support.
Nickel has been selected because it boosts the hydrogenating activity.
The HR-348 and HR-448 are desulphurization catalysts; it consists of
cobalt and molybdenum oxides dispersed on an active alumna. Its fine
granulometry and large surface area allow a deep desulphurization
Different catalysts based on Nickel and Molybdenum Oxide are used to
enhance the rate of reactions.
Sl. No. Products wt%
1 Off-Gas 1.36
2 Wild-naptha 1.04
3 Diesel 97.1
Diesel Hydro Treatment Unit (DHDT)
Objective : To meet the EURO-III/IV diesel quality requirement
Feed : Straight run diesel / FCC diesel component/ Coker and
Visbreaker diesel components.
Catalyst : Ni-Mo oxides
Sl. No. Products wt%
1 Off-Gas 2.65
2 wild-naphtha 2.8
3 Diesel 96.1
Wild naphtha feed from existing DHDS unit is processed along with
DHDT wild naphtha in a stabilizer located inside DHDT battery limits for
producing single naphtha product.
Processes in DHDT:
Refining & hydrogenation:
Removal of heteroatom (S, N2, O2) Saturation of olefins and
Hydrodesulfurization reactions are fast and take place in single
Mercaptans: R-SH + H2 R-H + H2S
Sulfides: R-S-R + 2H2 2R-H + H2S
Aromatic saturation & denitrification of heterocyclic compounds.
Hydroisomerisation & then cracking into lighter isoparaffins.
Once Through Hydro-Cracker Unit (OHCU)
Hydrocracking is a extremely versatile catalytic process in which feed
stock ranging from Naphtha to vaccum residue can be processed in
presence of hydrogen and catalyst to produce almost any desired
product lighter than feed. Thus if the feed is Naphtha it can be
converted into LPG if feed is VGO it can produce LPG, Naphtha, ATF,
Depending upon the feed quality, product mix desired and the capacity
of unit, following process flow configuration can be adopted for
Single stage – for 100% conversion
Two stage – for 100% conversion
Once through – for partial conversion of feed to products 60-80%
In single stage, the unconverted material from fractionator, bottom is
recycled to first reactor along with fresh feed. In two stage the
unconverted material is routed separately to another reactor.
Products of HCU
Stabilized light Naphtha
high Speed Diesel
In Hydrocracker the VGO feed is subjected to cracking in reactor over
catalyst beds in presence of Hydrogen at pressure of 185Kg/cm2 and
temperature from 365-441 C. the cracked products separated in
fractionator. Light ends are recovered in Debutanizer column. The
process removes almost all S and N from feed by converting them into
H2S and NH3 respectively, thus the product obtained are free of sulfur
and nitrogen compound and saturated. Therefore except for mild NaOH
wash for LPG , post treatment is not required for other products.
UNITS OF HCU
Make up hydrogen section
Light ends recovery section
Make up Hydrogen Compression section
The makeup Hydrogen Compression section consist of three identical
parallel compressor trains, each with three stage compression during
normal operation two trains are in use and compress makeup hydrogen
form a pressure swing adsorption (PSA) unit to reaction section the
compressed makeup hydrogen is combine with hydrogen recycle gas in
the reaction to form reactor feed gas. The makeup hydrogen
compression section is also used to compress a mixture of nitrogen and
air during catalyst regeneration.
The reaction section contains one reaction stage in a single high
pressure loop. Due to reactor weight limit of approximate 400 M Ton.
The reaction section consists of two reactors in series. The hydro-
treating & hydro-cracking reactions taking place in the reaction stage
occurs at high temperature and pressure. A high hydrogen partial
pressure is required to promote the hydro0cracking reaction and to
prevent coking of the catalyst. An excess of hydrogen is recirculated in
the reactor loop for reactor cooling to maintain a high hydrogen partial
pressure and to assure even flow distribution in the reactors.
It is used to separate reaction section products into sour gas, un-
stabilized liquid naphtha, heavy naphtha, kerosene and diesel.
Furthermore, bottom containing un-converted product servers as feed
to the FCC unit or is sent to tankage. The sour gas and un-stabilized
naphtha are sent to the light end section to make fuel gas, LPG and light
Light Ends Recovery section
Light naphtha from the fractionator is sent to de-ethanizer, where gas
are removed and sent to amine absorber where the H2S is absorbed in
the Amine and H2S free fuel gas is sent fuel gas system. Rich Amine
with dissolved H2S is sent to Amine Regeneration unit in sulfur recovery
unit. The bottom of dethanizer is sent to debutanizer. For the recovery
of LPG, LPG is taken out from the top and sent to treating section
where it is washed with caustic for removal of H2S. the stabilized
naphtha from the bottom of the stabilizer is sent to hydrogen unit to
OHCU FLOW SHEET
Hydrogen Generation Unit (HGU)
Objective : To Meet the Hydrogen requirement for
DHDS/DHDT/OHCU/ISOM/Reforming Units and Other Hydrotreaters.
Feed : Natural Gas / Naphtha and Feed
Co-Mo for Hydrotreater
ZnO/K2Co3 for H2S and Chloride adsorber
NiO for Preformer
Ni for Reformer
CuO for HT/LT Shift reactors
Adsorbents(molecular sieves) for PSA Adsorbers
HGU Product is 99.99% Pure H2
Operating Conditions :
Temperature range : 860-870 C
System Pressure : 20-38 kg/cm2
Even traces of sulphur is poison to Reformer Catalyst. Sulphur guard is
provided to reduce feed sulphurto <50 ppb. Pre Reformer reduce the
load on the reformer by converting the heavier molecules to methane
at relatively lower temperature.
The Shift reactor maximize the H2 production by Shift reaction (i.e. CO
+H2O H2 +CO2).
Sophisticated process Interlocks are provided as reformer operates at
very high temperature and it is prone to coking in absence of steam.
Reformer furnace draft is critically controlled by variable frequency
drive of FD/ID fan.
In IOCL mathura refinery there are two hydrogen generation units:
HGU-I & HGU-II
The Hydrogen plant is designed for production of 34,000 MTPY of
Hydrogen. Process licensor for HGU is HTAS, Denmark. The plant is
divided into 3 sections.
The hydrogen generation unit can be fed either by naphtha or natural
gas. The naphtha feed is pressurized to about 35 Kg/cm2g by one of the
naphtha feed pumps and sent to the desulphurization section.
The pressurized feed is mixed with recycle hydrogen from the hydrogen
header. The liquid naphtha is evapourated to one of the naphtha feed
vapourizers. The hydrocarbon feed is heated to 380°-400 O
C by heat
exchange with superheated steam in the naphtha feed pre-heater.
The desulphurization takes place in two steps. The first catalyst in the
desulphurization system is a cobalt-molybdenum hydrogenation
R1 – S – R2 + 2H2 → R1 – H + R2 – H + H2S
Having passed the hydrogenation catalyst in the first reactor the
hydrogenated process feed is sent to the sulphur absorbers. Here the
H2S formed is absorbed by the ZnO absorption catalyst.
ZnO + H2S → ZnS + H2O
The concentration of sulphur leaving the absorbers shall be lower than
The mixture of gas and steam (the process gas) is heated to
C. The preheated process gas passes the pre-
converter, where all higher hydrocarbons are converted into methane,
hydrogen, carbon monoxide and carbon dioxide.
The pre-converted process gas is further preheated to approximately
650°C in the reformer feed preheat coil before it is sent to the tubular
reformer containing 126 catalyst tubes maintained at desired
temperature. The reformer effluent leaves the tubes at a temperature
of approximately 930° C.
The Hydrogen plant is designed for production of 74,000 MTPA of
Hydrogen. Here also stem reforming of natural gas or naphtha is done
to produce hydrogen.
HGU-II has following processes:
High Temperature shift Reaction
Low Temperature shift reaction
HGU-II Furnace has top fired burners. HGU-II has 12 PSA Drums.
Asphaltic bitumen, normally called "bitumen" is obtained by vacuum
distillation or vacuum flashing of an atmospheric residue. This is
“straight run" bitumen. An alternative method of bitumen production is
by precipitation from residual fractions by propane or butane- solvent
The bitumen thus obtained has properties which are derived from the
type of crude oil processed and from the mode of operation in the
vacuum unit or in the solvent de-asphalting unit. The grade of the
bitumen depends on the amount of volatile material that remains in
the product: the smaller the amount of volatiles, the harder the
residual bitumen. The blowing process for bitumen preparation is
carried out continuously in a blowing column. The liquid level in the
blowing column is kept constant by means of an internal draw-off pipe.
This makes it possible to set the air-to-feed ratio (and thus the product
quality) by controlling both air supply and feed supply rate. The feed to
the blowing unit (at approximately 210 0C), enters the column just
below the liquid level and flows downward in the column and then
upward through the draw-off pipe. Air is blown through the molten
mass (280-300 0C) via an air distributor in the bottom of the column.
The bitumen and air flow are countercurrent, so that air low in oxygen
meets the fresh feed first. This, together with the mixing effect of the
air bubbles jetting through the molten mass, will minimise the
temperature effects of the exothermic oxidation reactions, local
overheating and cracking of bituminous material. The blown bitumen is
withdrawn continuously from the surge vessel under level control and
pumped to storage through feed/product heat exchangers.
Air residue having boiling point 530o
C (TBP) is obtained from North
Rumaila crude. Air blowing of vacuum residue at high temperature
considerably increases the contents of gums and asphaltenes at the
expense of conversion of a portion of hydrocarbon into condensed oil.
Bitumen is a colloidal solution of asphaltenes and associated high
molecular gums in the medium formed by oils and low molecular gums.
Asphaltene content in the bitumen influences its solidity and softening
point. The higher the asphaltene content, the more solid is the
bitumen. Gums increase bitumen binding properties and elasticity.
Amine Recovery Unit (ARU)
Diethanol amine almost saturated with H2S (rich amine) and received
at battery limit from DHDS, FCC, OHCU unit is processed in unit ARU to
separate out H2S and amine solution (lean amine), which is obtained as
bottom product from ARU. H2S and other light components present in
the rich amine are separated out as overhead product.
AMINE FLASH DRUM
The rich amine containing absorbed H2S and CO2 from amine absorber
and LPG MEROX units enter the amine flash column at a pressure of
about 5 kg/cm2 and temperature of 55O
C. Height of flash column is
approximately 11.4 in. and dia. = 500 mm at the top and 1600 mm at
the bottom of section. Top section is packed with raschig rings. Rich
amine at 5 kg/cm2 is flashed into the column to a pressure of 2.8
kg/cm2. The bottom section contains four single pass valve trays.
Because of flashing, hydrocarbons in the amine get liberated, thereby
reducing the quantity of hydrocarbons going with sour gas to sulphur
unit, which spoils the catalyst.
The liberated hydrocarbons from the top of the column enter the flare
header through a pressure control valve. The column top pressure is
maintained at 2.8 kg/cm2. When column pressure rises, a valve opens
and lets off the liberated hydrocarbons to flare and when pressure
drops pressure valve opens for fuel gas (FG) to enter the column.
A slipstream reflux of lean amine solution is fed into the top of column
above the packing to reabsorb any H2S liberated during flashing from
the bottom of the flash column.
In amine regeneration the rich DEA is stripped of its absorbed sour
gases H2S and CO2 using steam. So regenerated amine can be reused in
absorber. Amine reboiler is heated by LP steam. Steam strips off the
absorbed H2S and CO2 present in the DEA solution.
Reactions involved are:
R2NH3S R2NH + H2S where R = CH3CH2OH
The top temperature of regenerator is about 105o
C and middle
temperature is about 115 o
C. Pressure is nearly 0.5 kg/cm2. The
liberated sour gases leave the regenerator from the top and enter the
overhead condenser where gases are cooled and steam is condensed to
C. Sour gas from the reflux drum top goes to the sulphur recovery
plant by the production of Sulphur.
Reboiler has two compartments separated by a baffle. By heating the
compartment DEA overflow above the baffles to the other
compartments from where it flows to regenerator by gravity.
The excess pressure drop is due to foaming of amine inside the column.
So, antifoaming agent dosing is needed. Foaming is caused due to
contamination of amine solution by condensed light hydrocarbons, fine
suspended solids or surface-active agents.
A portion of cold lean amine is passed through charcoal filter to remove
iron impurities due to corrosion and to a sand filter to absorb charcoal
and sent to suction line of lean amine pump.
Sulfur Recovery Unit (SRU)
Objective: To Reduce the SO2 emission from the Refinery by recovering
Sulphur from Amine Acid and Sour Gases produced during various
Feed : Amine Acid gases and Sour acid gases
Temperature Range : 195-320 Deg C
Pressure: 0.56 kg/cm2(g)
Sl. No. Products wt%
1 Off-Gas 0.1
2 Sulphur 99.9
Chemical reactions in SRU:
The main reaction (PARTIAL OXIDATION) in the main burner is :
H2S + 3O2------> SO2+ H2O +heat
The major part of the residual H2S combines with the SO2 to form
sulphur, according to the equilibrium reaction :
2H2S + SO2< -------> 3S2+ 2H2O -heat
By this reaction , known as the Claus reaction, sulphur is formed in
vapour phase in the main burner and combustion chamber.
Motor Spirit Quality Unit (MSQU)
Objective : To Upgrade the Naphtha by increasing its Octane Number
to Higher Octane/Low Benzene/Low Olefins MS Component
(Isomerate) to Meet Euro III / IV MS Specifications.
Feed: C5-85 Deg C cut Naphtha /FCC gasoline(70-90 deg C cut)/ Lt.
Catalyst: Co-Mo for HydrotreatorReactor
Pt for PenexReactor
Ni Based for Methanation
Naptha hydrotreating unit
Reformate splitter unit
Temperature range : 126-145o
System Pressure : 33.5 kg/cm2
Sl. No. Products wt%
1 Motor Spirit 90-91
2 LPG 10-11
MSQU process technology is used for production of blending stream of
gasoline to meet stringent quality of MS w.r.t. benzene & aromatics
Purpose of Naphtha hydro treating process:
It is used to remove Penex catalyst poisons from light naphtha prior to
charging to Penex process unit. UOP Naphtha hydrotreating process is
catalytic refining process employing a UOP hydrotreating catalyst and a
hydrogen rich gas stream to decompose organic sulfur, oxygen and
nitrogen compounds contained in the naphtha fraction.
In addition, hydrotreating removes organo-metallic compounds and
saturates olefinic compounds. Organo-metallic compounds such as
arsenic, lead & silicon compounds are known to be permanent poison
to platinum containing catalysts.
Purpose of reformate splitter:
Split C6 & lighter species from the heavier reformate in the
Overhead vapor from reformate splitter is then condensed
and collected in reformate splitter receiver. This stream is
mixed with stream from separator of NHT unitand sent as
feed to Penex-DIH unit through sulfur guard.
Prime G Unit
Objective: Removal of sulfur from FCC gasoline with minimum octane
loss to meet norms of EURO-IV in MS.
Feed : FCC Gasoline
Total Sulphur in Product: ≤100 ppmw
Technology: Prime G
Selective Hydrogenation Unit (SHU)
Gasoline Splitter Unit(GSU)
Hydro-desulphurization Unit (HDU)
SHU Reactor: Feed comes from Heart cut of FCC. Only Diolefins are
hydrotreated and light mercaptans are converted into heavy
mercaptans. Now this product is sent to splitter unit, where it is split
into Light cut naphtha(LCN) & Heavy cut naphtha(HCN)
Gasoline splitter Unit: splits the products from SHU reactor into LCN
HDS Unit: Olefin saturation is very limited and no aromatic
Catalyst: Co-Mo based catalyst.
Sl. No. Products wt%
1 LCN 23
2 heart Cut 15
3 HCN 62
FLOW SHEET OF MATHURA REFINERY